Seismic Acquisition Method and Apparatus

ABSTRACT

A technique for use in geophysical surveying includes imparting a plurality of humming seismic signals and a plurality of low-frequency seismic signals into a geological formation. The technique also includes receiving returned seismic energy of the plurality of humming seismic signals and the plurality of low-frequency seismic signals after interacting with the geological formation and recording the returned seismic energy.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. patent application Ser. No.14/957,363 filed Dec. 2, 2015, and entitled “Seismic Acquisition Methodand Apparatus,” which claims the benefit of U.S. Provisional PatentApplication Ser. No. 62/086,581 filed Dec. 2, 2014, and entitled“Seismic Acquisition at Low Frequencies with Deeply Towed, Heavy SeismicSources,” both of which are hereby incorporated herein by reference inits entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

The technique disclosed herein pertains to seismic surveying and, moreparticularly, to marine surveying at low frequencies.

The pursuit of hydrocarbons and some other fluids is sometimes greatlyhampered by their being located in deposits underground in certain typesof geological formations. Such deposits must be identified and locatedby indirect, rather than direct, observation. This includes impartingacoustic, or sound, waves of selected, seismic frequencies into anatural environment so that they may enter the earth and travel throughthe subterranean geological formations of interest. During their travelsthrough the formations, certain features of the formations will returnwaves back to the surface where they are recorded. The seismic data thusrecorded contains information regarding the subsurface geologicalformations from which one can ascertain things like the presence andlocation of hydrocarbon deposits. That is, seismic data arerepresentative of the geological formations from which they areobtained.

For example, one tool frequently used in the analysis of the seismicdata is what is known as a “velocity model”. A velocity model is arepresentation of the geological formation that can be used in analysis.It may be used to, among other things, convert the seismic data into oneor more “seismic domains” that image the geological formation indifferent ways. The quality of these images frequently depends upon thequality of the velocity model. It may also be used in other ways to, foranother example, analyze various geophysical characteristics of theformation. Other types of models of the underlying geologicalformations, collectively called “subsurface attribute models” herein,are also used and implicate similar considerations in the presentcontext.

Over time, the need to locate hydrocarbon deposits more accurately andmore precisely has grown. Sometimes advances in accuracy and precisioncome in the form of new acquisition techniques. Other times suchadvances are achieved through the manner in which the seismic data areprocessed such as those described in the above. Sometimes advancesresult from a combination of developments in both acquisition andprocessing.

A relatively recent development in seismic acquisition is“low-frequency” acquisition. Seismic surveying historically has usedfrequencies in the range of 8-80 Hz for seismic signals because of theirsuitability in light of technical challenges inherent in seismicsurveying. The term “low frequencies” is understood within thishistorical context as frequencies below which getting sufficient signalto noise with conventional sources rapidly becomes more difficult as thefrequency decreases, i.e. below about 6-8 Hz.

The use of low frequencies for imaging marine seismic data has provenchallenging for frequencies below about 6 Hz, particularly forfrequencies below about 4 Hz. The challenge is twofold: (1) at lowerfrequencies, the naturally occurring seismic background noise of theEarth gets progressively stronger and (2) conventional broadband sourcessuch as airguns get progressively weaker. As a result, thesignal-to-noise of deepwater marine seismic data can decline at over 30dB per octave for frequencies below 4 Hz.

Thus, while there may be many suitable techniques for seismic imaging ingeneral and for generating subsurface attribute models in particular,the need for increased effective signal-to-noise ratios, at lowfrequencies, continues to drive innovation in the art. In particular,among other things, there is a need for acquisition and processingtechniques that enhance acquisition and use low-frequency seismic dataat lower frequencies. The art is therefore receptive to improvements orat least alternative means, methods and configurations that mightfurther the efforts at improvement. As a result, the art will welcomethe technique described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, which are incorporated in and constitute apart of this specification, illustrate embodiments of the invention andtogether with the description, serve to explain the principles of theinvention. In the figures:

FIG. 1 conceptually illustrates a marine seismic survey conducted inaccordance with one particular embodiment of the presently disclosedtechnique.

FIG. 2 conceptually depicts the deployment of the nodes for alternativeembodiments of the marine seismic survey of FIG. 1.

FIG. 3 depicts a retrieval technique as may be used in some embodiments.

FIG. 4 depicts an alternative embodiment in which the seismic source istowed from the stern rather than the side of the source vessel.

FIG. 5 illustrates a method for towing incorporating avortex-induced-vibration suppression system as is used in the embodimentof FIG. 4.

FIG. 6 illustrates a “simultaneous hum-sweep-bang” acquisition conceptgraphically.

DESCRIPTION OF THE EMBODIMENTS

The presently disclosed technique acquires seismic data at low seismicfrequencies to generate better starting models for subsurfaceattributes, rather than for enhancing the bandwidth of airguns forbroadband imaging as in conventional practice. Such models need not beperfect, but only adequate as a starting model for an iterativerefinement in this approach, using model-updating techniques such asFull-Waveform Inversion (“FWI”). Furthermore, it would be useful toupdate subsurface attribute models to relatively deep depths.

This raises the question of what low frequencies are desirable. One areaof interest in seismic surveying is salt formations. For a salt 3 kmthick with a velocity of 4600 m/s, a half wavelength at zero offsetfitting inside the salt would implicate a frequency of(4600/2)/3000=0.77 Hz. By going to wider offsets, the frequency does nothave to get this low to get the same vertical wavenumber. Nevertheless,the involved frequencies are below what those in the art expect to beable to produce using airguns, even very large ones. Notably,conventional seismic imaging mostly uses streamers, not nodes.Unfortunately, streamers generate considerable noise at frequenciesbelow about 4 Hz, which are of most interest, compounding thesignal-to-noise ratio problem at low frequencies.

With respect to updating subsurface attribute models to relatively deepdepths, the rule of thumb is that the depth of penetration of divingwaves (and thus FWI updates) is generally about ⅓ of the maximum offset.So, for example, to improve a subsurface attribute model to a depth of10 km, the survey should therefore employ offsets out to at least 30 km.That is, for most sources, there should be receivers at a range ofoffsets out to 30 km away from the source.

These factors impact other aspects of the survey design. The frequenciesunder discussion are low, such that even by the conservative Nyquistsampling criterion, a principle of sampling theory well known to thosein the art, the survey does not need sources and receivers at the sampleintervals typical for conventional acquisition. The Nyquist samplingcriterion applied to source and receiver spacing is “2 points perwavelength along the recording surface”. Typical shot densities inconventional acquisition are 50 meters apart or less, which at a watervelocity of 1500 m/s is well sampled by the Nyquist criterion forfrequencies of (1500 m/s/50 m)/2=15 Hz or less. For waves of 2 Hz theNyquist criterion would require a source or receiver only every (1500m/s/2 Hz)/2=375 meters. A typical ocean-bottom-node density inconventional acquisition of 430 meters becomes well sampled by theNyquist criterion at frequencies of 1.74 Hz or less. Thus, whether theshot or receiver density is well sampled depends on the frequency underconsideration.

Effective FWI can be obtained with either the source or the receiverside well sampled, rather than both. So, where the source side is wellsampled the receivers can be much coarser than the ˜400 meters suggestedby the Nyquist criterion, i.e. 2 km apart or more.

Alternatively, the low-frequency acquisition may make use of anocean-bottom node grid laid out for acquisition at conventionalfrequencies, a so-called “piggyback” survey. Then a typical ocean-bottomnode spacing of about 400 meters, a coarse (i.e., not sampled within theNyquist criterion) grid at conventional frequencies, may be sufficientto ensure the receivers are well sampled by the Nyquist criterion forsufficiently low frequencies. With the receiver side well sampled, thelow-frequency shot lines may then be spaced much coarser than this, i.e.2 km apart or more.

Note it is often computationally more efficient to have the receiversmore finely sampled than the sources when performing computations. Theprinciple of seismic reciprocity can be used to reverse the roles ofsources and receivers for the purposes of the computation to make thisso, as is well known to those of ordinary skill in the art. Thus eitherthe physical sources or receivers may sample the computational“receiver” wavefield.

In practice FWI can often produce usable results even if the Nyquistsampling criterion is not met by either the source or receiveracquisition. FWI works by back-propagating a residual wavefield (thedifference between the wavefield predicted at the receivers and what wasactually measured there). Thus, for the purposes of updating thevelocity model, it is the sampling of the residual wavefield, not thereceiver wavefield, that matters. If the velocity model used to createthe predicted wavefield is a good approximation of the true velocitymodel, the rate of change of the phase of the predicted and measuredreceiver wavefields will be similar. The phase difference between these(i.e. the phase of the residual wavefield) will then accumulate withdistance rather slowly. The wavelength of the residual wavefield maythus be considerably larger than the wavelength of the receiverwavefield, allowing a correspondingly larger receiver spacing to sufficefor representing the residual wavefield.

How far the sampling can be pushed beyond the Nyquist criterion dependson the (unknown) accuracy of the velocity model. In practice, the choiceof source and receiver spacing is a balance between how much faith weare willing to place in our velocity models and cost. For both shots andreceivers, finer inline sampling is typically much less expensive toobtain than finer crossline sampling, and hence the limiting factor ismost often the crossline spacing of either the sources or receivers.

In the present context, “inline” and “crossline” are well defined for ashot line. Inline is the direction the boat traveled. Crossline isorthogonal to the inline direction. In the case of an ocean bottomreceiver array, with similar spacing in Cartesian coordinate X and Yorthogonal directions, “inline” and “crossline” will be determinedrelative to the shot lines of the survey. However, in the case where theocean bottom receiver array spacing is not the same, “inline” is thedenser axis and “crossline” is the coarser axis. Typically, in thatcase, the inline direction would be the direction the ROV moved when itdeployed the nodes. Economic considerations will generally dictate thatthe crossline spacing will be greater than or equal to the inlinespacing.

Another well-known design consideration in a marine seismic survey isthe far-field effect of the sea-surface reflection, in particular the“ghost notch” at 0 Hz. In the approach disclosed herein, the survey towsthe sources and, in some embodiments the receivers, as deep as isfeasible to mitigate the deleterious effects of the ghost notch. Inaddition, the sources are heavy, and so are towed at a steep tow anglein the embodiments illustrated herein.

Thus, this particular approach embodies a number of unique designprinciples such as deeper, heavier tow, minimized low-frequency noise,very wide source-receiver offsets, and sparse acquisition (as comparedto conventional practice) in varying permutations depending upon theembodiment. The presently disclosed technique therefore employs awide-offset, ocean-bottom-node geometry as disclosed more fully below toaccommodate these concerns.

The deeper tow principle also implies towing the seismic source(s)deeper than is typical for airguns as well. In one particular embodimentof the disclosed technique, the seismic source is heavy enough to hangnearly vertically underneath the source vessel. This is referred to, forpresent purposes, as a “heavy tow”.

The heavy tow is distinguishable from conventional practice by theweight on the towline. In conventional practice, the tow body (e.g., theseismic source) is approximately neutrally buoyant in water and itsweight is not significantly supported by the towline. In fact, depressorweights are quite often used to decouple the tow body entirely from thevertical component of the tow. In a heavy tow, the tow body is notneutrally buoyant and the towline carries a significant weight. In someembodiments, the towline may carry up to several tons. Within thecontext of this disclosure, a heavy tow is one in which the seismicsource is heavy enough be towed at a steep tow angle as discussedfurther below.

Heavy tow has some advantages. One benefit of the heavy tow is that theseismic source need not be towed behind the source vessel, but couldinstead be towed from the side of the source vessel. The middle of thevessel moves less than the stern in rough seas, keeping the seismicsource at a more stable tow depth. Towing the seismic source from theside of the source vessel would thus have the advantage of minimizingthe heave on the seismic source tow line. This is useful because depthchanges may alter the resonant frequency of the seismic source orproduce large tensions on the tow line. In this particular embodiment,the depth of tow is determined by the performance of the device as afunction of depth balanced against the advantages of a deeper tow inminimizing the deleterious effects of the ghost notch at 0 Hz. Inalternative embodiments, the depth of tow may be limited by the waterdepth, the weight and strength of the tow cable, or otherconsiderations.

The heavy tow described above also relaxes vessel speed considerationsin that vessel speed need not be maintained to keep a stable tow linetrailing behind the source vessel. Instead, the source vessel only needsto go fast enough to keep the source vessel itself under good controland, in some embodiments, the seismic source stably oriented. The vesselspeed may therefore be controlled by how long it takes for the seismicsource to generate sufficient energy in the desired frequency range overone “shot point”; the width of the shot point being determined by theNyquist criterion for the highest frequency of interest. If more energyper shot point is desired, it may be obtained simply by towing theseismic source more slowly. If the source vessel is capable ofmaintaining a fixed location, and stability of the seismic source is notan issue, it can even pause and emit energy for as long as necessary ateach shot location.

Heavy tow also has some disadvantages. As is known to those of skill inthe art, tow lines may be susceptible to vortex-induced vibration(“VIV”), and the taut, steep tow line supporting the weight of thedevice may be especially susceptible to VIV. Some sort of VIVsuppression may be required to keep the tow line(s) from strumming dueto their motion through the water. It may be necessary to havealternative shot line orientations planned to avoid aggravating the VIVdue to sailing against a strong current.

Under heavy tow, some sort of system, such as a heave compensator, maybe employed to prevent vertical motions of the ship from beingtransmitted to the device. VIV suppression typically involvessurrounding the tow line with, for example, fluffy material oraerodynamically shaped cladding. It may be impractical to design orprocure a heave compensator that accepts a weight-supporting tow lineequipped with VIV suppression. The heave compensation may need to be“indirect”, with a line that will fit through the heave compensatorcontrolling the motion of another line fitted with VIV suppression thatis attached to the device.

In light of the considerations set forth above, the presently disclosedtechnique uses, in various embodiments, widely spaced ocean-bottom nodes(˜2 km apart) placed out to very wide source-receiver offsets (≥15 km,and up to at least ˜30 km), shot lines much more widely separated (˜400meters apart) than for conventional acquisition (but well sampled forsufficiently low frequencies), a survey vessel of the kind that mighttow a remotely operated vehicle (“ROV”) rather than a typical streamervessel, and a deep seismic source (depths of 30 m or more) towed fromthe side of the source vessel. The source vessel includes some sort ofheave compensation to keep the depth steady and reduce stress on the towline, and some sort of VIV suppression to keep the taut tow line fromstrumming in some embodiments.

Furthermore, FWI typically only requires pressure data, recorded byhydrophones. If a survey design only needs hydrophone recordings,receivers used in nodes could be deployed from a basket moved along tensof meters above the sea floor. The nodes are dropped from the basket andfall the short distance to the sea floor. These nodes might be retrievedby having a buoyant streamer above them in the water that could besnagged with a similar “fly-by” technique.

Note that not all embodiments will possess all of these characteristics.For example, even though ocean nodes may be coarsely spaced (2 km ormore in the receiver crossline direction), some embodiments (for example“piggyback” surveys) may choose to space them at conventional distances(450 m or less in both the inline and crossline directions). In thiscase because the receivers are well sampled (at sufficiently lowfrequencies), the shot lines do not need to be well sampled, even forlow frequencies, and so may be even more coarsely spaced (2 km or more).

Similarly, some embodiments may choose to simultaneously deploylow-frequency sources and conventional sources, and thus may use aconventional spacing for low-frequency shot lines (50 m or less) ratherthan widely spaced shot lines (˜400 m or more) as in other embodiments.The shot and receiver lines may be oriented orthogonally to each other,each coarsely spaced in its crossline direction, but well sampled (lessthan about 400 m) in its inline direction. Additional informationregarding this particular design may be found in the U.S. PatentApplication having priority to U.S. Provisional Application No.62/086,362, entitled, “Box Wave Arrays in Marine Seismic Surveys”, filedon an even date herewith in the name of the inventors Andrew J.Brenders, et al., and commonly assigned herewith. Those in the arthaving the benefit of this disclosure will appreciate still otherpermutations that may be implemented in alternative embodiments.

Reference will now be made in detail to the present embodiment(s)(exemplary embodiments) of the invention, an example(s) of which is(are) illustrated in the accompanying drawings. Wherever possible, thesame reference numbers will be used throughout the drawings to refer tothe same or like parts.

FIG. 1 conceptually illustrates a marine seismic survey acquisition 100conducted in accordance with one particular embodiment of the presentlydisclosed technique. The marine seismic survey 100 is conducted using atleast one low frequency seismic source 103 towed by a source vessel 106.It also includes a plurality of receiver lines 109 disposed upon theseabed 112. In this context, “low frequency” means <4 Hz. Each receiverline 109 includes several nodes 115, which, in the illustratedembodiment, are hydrophones; although in alternative embodiments theymay be geophones or multicomponent receivers. In other embodiments, “lowfrequency” means <6 Hz.

This one, particular embodiment uses a deployment 200 illustrated inFIG. 2 for the nodes 115. This particular embodiment is disclosed morethoroughly in U.S. Pat. No. 6,975,560, modified as described herein. Thenodes 115 are disposed from a carrier 201 suspended from a survey vessel203 using an ROV 206 at the end of a tether management system 209.Similarly, the nodes 115 are also retrieved to the carrier 201 using theROV 206 and then to the survey vessel 203. Additional information on howthis operation is conducted may be found in U.S. Pat. No. 6,975,560.

The nodes 115 may be retrieved in this particular embodiment as is shownin FIG. 3. Each node 115 rests upon the seabed 112 as described above. Abuoyant element—e.g., a buoyant, tethered buoy 116—extends from one endand floats above the node 115. The tether 117 may itself be buoyant ormay rely upon the buoyancy of the buoy 116. The buoy 116 includes a hook300 or other similar structure extending from the end opposite theattachment of the tether 117. Note that the size, weight, and placementof the hook 300 should be such that it remains oriented upright as shownin FIG. 3 rather than rotating downward.

Because the buoy 116 floats above the seabed 112 and the node 115, it isamenable to retrieval using a towed grappling device 305 in a “fly by”of the receiver line 109. The grappling device 305 may be towed by, forexample, the remotely operated vehicle (“ROV”) 206 or a surface vessel.Once grappled, the ROV 206 can then be used to place the nodes 115 backinto the carrier 201. Once the carrier 201 is full, or all the nodes 115are retrieved, the carrier 201 can then be lifted to the surface vessel203. Alternatively, the grappled nodes 115 may be retrieved directly tothe surface.

Many variations of this “fly-by” technique are possible. In alternativeembodiments the buoy 116 might be above the hook 300, or the hook 300could be replaced by a block of ferrous metal and the grappling device305 by an electromagnet, etc.

The presently disclosed technique admits further variation in thedeployment and retrieval of the nodes 115. For example, a type ofsurveying known as electromagnetic, or “EM”, surveying conventionallyuses what are known as “pop-up” nodes. Such nodes are deployed from overthe side of a source vessel and permitted to free fall to the seabed,where their resting positions may be determined by acoustic rangingmethods well known in the art. When the seismic survey is completed, asignal is sent to the nodes from the surface ordering them to releasetheir anchors and float back to the surface—or, “pop up”. The anchor maybe made from a substance that harmlessly dissolves in sea water over aperiod of months, and in some cases, up to a few years. Some embodimentsmay forego the signal release in favor of a timed release. Someembodiments may replace the anchor with a swim bladder, for example, byreplacing water in a chamber with gas to cause the node to pop up.

In another embodiment particularly suited to deployments in shallowwater, the nodes may be attached or built into an ocean-bottom cablethat is spooled out from a moving ship and allowed to sink to the seafloor. The ocean-bottom cable is then later snagged at one end, the endlifted, and the cable spooled back onto the ship in reverse fashion tohow it was deployed. These and other such variations are all within thescope of the claims set forth below. It should be noted that suchmethods are particularly suited to deployment and retrieval ofhydrophones, since these do not need to be either carefully coupled tothe seafloor or precisely oriented.

The embodiment of FIG. 2 envisions shots that are sufficiently denselyspaced in both the inline and crossline directions (˜400 m or less) thatthe receivers do not need to be spaced according to the Nyquistcriterion. The embodiment of FIG. 2 therefore uses coarsely spacedocean-bottom nodes 115. In this context, “coarsely spaced” means a nodespacing N_(s) of greater than or equal to ˜750 m, or about double theNyquist criterion at 2 Hz. Some embodiments may employ a node spacingN_(s) greater than or equal to ˜1 km, or ˜2 km, or ˜4 km. Someembodiments may employ a node spacing that is approximately equal alongboth axes, such as is shown in FIG. 2.

Alternative embodiments may achieve a greater efficiency in deployingand retrieving the nodes by using a node grid in which the nodes arespaced apart more coarsely along one axis than the other, for example aninline node spacing of ˜400 m but a crossline spacing of ˜800 m, or ˜1km, or ˜2 km, or ˜10 km. Crossline node spacing greater than about 2 kmwould not be practical for conventional imaging purposes, but can bepractical for the purposes of the invention because the goal is notdetailed imaging of reflectors, but merely “improved starting velocitymodels”.

Note in particular that if the nodes are deployed from an ROV, there maybe little advantage in using an inline node spacing of much greater thanabout 400 m, because for wider spacing the time the ROV spends layingdown the node is no longer the dominant factor determining cost; insteadit becomes the time it takes the ROV to transit from one node locationto the next. Similarly, conventional ocean-bottom cables have a nodespacing of about 50 m, and thus the inline spacing for these is fixed.The acquisition cost is determined by how many cables are required,which is determined by the crossline node spacing, which will be chosento be as coarse as possible given the geophysical objectives, andtypically will be much larger than 50 m. However, for other embodimentssuch as autonomous nodes, which swim to a pre-set position and plantthemselves, the determining cost may be the total number of nodes andnot their spacing, in which case there may be little reason to choose touse a wider spacing along one node axis than the other.

Returning now to FIG. 1, as noted above, the source vessel 106 tows atleast one low frequency seismic source 103. In some embodiments, the lowfrequency seismic source 103 may be towed from the stern of the sourcevessel 106 in conventional fashion. However, in the illustratedembodiment, the low frequency source(s) 103 is/are towed from the sideof the source vessel 106 as is shown in FIG. 1.

In the illustrated embodiment, sources 103 are low-frequency hummingand/or narrowband sweeping sources. A “humming” source radiates the bulkof its energy at a single monochromatic frequency, or a small number ofmonochromatic frequencies. A “narrowband sweeping source” sweeps, butunlike a conventional broadband sweeping source only over a narrowfrequency range of less than two octaves. Each of the sources 103 willcontain a receiver or sensor (not shown) that will record the wavefieldemitted by that source. In one particular embodiment, the humming ornarrowband source is implemented using the source disclosed and claimedin U.S. Pat. No. 8,387,744. The signal produced by this source is notonly a low frequency signal, but also a narrowband signal. However, thetechnique is not limited to acquisition with this particular source.Alternative embodiments may utilize other types of low frequencysources.

In an alternative embodiment, the humming or narrowband source isimplemented using an embodiment of the source disclosed and claimed inU.S. application Ser. No. 14/515,223, entitled, “System and Method forResonator Frequency Control by Active Feedback”, filed on Oct. 15, 2014,in the name of the inventors Mark Francis Lucien Harper; Joseph AnthonyDellinger. In this embodiment, the source contains a low-frictionreciprocating radiating piston moving with a resonant frequencycontrolled by a two-sided variable gas spring. In one embodiment, theradiating piston is sealed against the external fluid pressure using theexternal fluid (typically sea water) to pressurize a hydrostatic seal.The frequency of oscillation of the radiating piston is determined bythe balance between the external and the internal fluid pressures. Theinternal fluid pressure is provided by a pair of gas springs. Thestiffness of the first gas spring is controlled by two squeeze pistons,not one, acting on a gas spring piston that is coupled to the radiatingpiston. This controllable gas spring operates in parallel with a secondfixed (i.e. non-controllable) gas spring comprising the body of thedevice.

The pair of squeeze pistons bounding the controllable gas springprovides two degrees of freedom that can be used when operating thedevice. Only one degree of freedom is required to control the resonantfrequency of the source. The other degree of freedom may then be used tocontrol the center of oscillation of the gas spring piston, and thus thebuoyancy of the source. Control of the buoyancy of the source allows itto be towed at a more stable depth. In some embodiments, a feedbackprocess analogous to the one that uses the squeeze pistons to controlthe resonant frequency may be employed to use the squeeze pistons tosimultaneously also control the buoyancy, so as to achieve a desiredstable tow depth.

In an embodiment, the extra degree of freedom may be incorporated intosweep profile design, i.e. the nominal design trajectories of the twosqueeze pistons bounding the controllable gas spring. The designtrajectories specify how the squeeze pistons should move with time overthe course of a sweep. One strategy, as stated above, is to design thetrajectories to maintain a constant buoyancy over the sweep. Thisstrategy can also be used to keep the oscillation of the gas springpiston centered within its available travel window, allowing it toachieve maximal amplitude in its oscillations while still maintaining aminimum desired safety margin from both travel limit endpoints.

However, in alternative embodiments where constant buoyancy is less of aconcern, the extra degree of freedom could instead be used to modify theacoustic properties of the sweep, for example to minimize or maximizeradiated harmonics of the fundamental tone. This requires using theextra degree of freedom to adjust the properties of the controllable gasspring so as to make the joint effect of all the springs operating inparallel, which together control the resonant motion of the piston,either more or less linear, respectively. The precise details of how toaccomplish this will depend on the design of the particular device beingused.

Other strategies are also possible for keeping the oscillation of thegas spring piston within its available travel window, and these may beused individually or in combination with other strategies. The measuredmotion of the piston can be used in a feedback loop to correct the towdepth in real time. In an exemplary embodiment, if the piston is indanger of encountering the outer limit of its travel, the tow depthwould be increased, applying more external pressure and moving thepiston back in. If the piston were in danger of encountering the innerlimit of its travel, the tow depth would similarly be decreased, movingthe piston outward.

Instead of a single profile, a suite of profiles may be provided atvarious amplitudes, to provide a “volume control” for the device. In anembodiment where the limits of motion of the piston are not beingsufficiently accurately maintained (for example because of rough seas,problems with the towing equipment, or inexperienced operators) a lessdemanding lower-amplitude profile that provides more clearance at bothends of the piston's travel may be used instead. The tow speed couldthen be adjusted along with the profile amplitude to maintain a constantsignal-to-noise per “shot point”. In an exemplary embodiment, alower-amplitude profile could be compensated for by allowing more timeper “shot point”, which requires using a profile that extends for longerin time, which in turn requires a slower tow speed for that longerprofile to fit into one “shot point” as determined by the Nyquistcriterion.

The low-frequency sources 103 are shown towed at deeper depths; in someembodiments multiple low frequency sources will be towed, each at adepth appropriate for its frequency range. Thus, the deeper the depth oftow, the lower the frequency of the humming or narrowband swept source.See, for example, U.S. application Ser. No. 12/291,221 or U.S. Pat. No.7,257,049, which discuss the relationship between depth and frequency ofacquisition. For some types of sources, the available frequency rangeshifts upwards with increasing depth, for example because an increase inwater pressure raises the resonant frequency of the source. Thus, inother embodiments the lower-frequency sources will be towed at shallowerdepths, despite the greater attenuation from the surface ghostreflection that this will cause.

Many variations of this acquisition are possible and well within theordinary skill in the art to devise with the benefit of this disclosure.The instant survey system shown in FIG. 1 could acquire 2D, 3D, or 4Ddata. Other recording systems could be used alongside or instead ofocean-bottom cables or nodes, including “nodes on ropes”, receiverssituated in a borehole, receivers dangling from wave gliders, receiversfloating in the water column, vertical cables, or low-noise deep-towstreamers. In an embodiment, nodes on ropes are ocean-bottom nodes thatare self-powered independent recording units which are strung on cablesthat are used to deploy them. Variations in the design of the spread orthe number of vessels will also be readily appreciated by those skilledin the art having the benefit of this disclosure.

The low-frequency narrowband survey could be performed at the same timeas a conventional, higher-frequency broadband survey, or in a separatepass, or in multiple separate passes. Or, a low-frequency narrowbandsurvey could be acquired first, and a conventional higher-frequencybroadband survey later. Or, a low-frequency narrowband survey could beused to supplement a previously acquired conventional higher-frequencybroadband survey such that the original data are re-processed with theadditional low-frequency data.

In one embodiment, the low-frequency data could be used to augment thebandwidth of the conventional higher-frequency data, thereby producingan image with enhanced bandwidth. The augmented data may be re-imagedusing the same velocity model as before.

In another embodiment, the low-frequency narrowband survey could beacquired in an area that has proven difficult to image using existingconventional higher-frequency data. The low-frequency narrowband datacould then be used with FWI to create an improved velocity model, whichcould then be refined using data from an existing conventionalhigher-frequency broadband survey. Then, the refined velocity modelcould be used to re-image seismic data from an existing conventionalhigher-frequency broadband survey, producing an improved image.

These two embodiments may also be used in combination, so thelow-frequency narrowband survey could first be used to improve thevelocity model, and then to enhance the bandwidth of the data re-imagedusing the improved velocity model.

The low-frequency sources 103 could operate continuously. Thelow-frequency sources 103 could each operate at a single frequency orcycle between two or more discrete frequencies (“humming” low-frequencysources), or sweep over a narrowband range of low frequencies designedto augment the frequency range produced by the broadband sources(“narrowband sweeping” low-frequency sources). The sources could operateto produce waves of constant amplitude, or the amplitude of the wavescould vary (taper up and down).

In the illustrated embodiment, two low frequency sources 103 hum at 1.4and 2.72 Hz, respectively. In other embodiments, a single sourcesimultaneously humming at a fundamental and a second harmonic, 1.4 and2.8 Hz, might be used, or a single source might alternate back and forthbetween 1.4 and 2.72 Hz. Other embodiments might realize such variationusing alternative frequencies within the ranges described herein.

Turning now to narrowband sweeping acquisition, there is no attempt tosweep over a sufficient bandwidth to make an interpretable seismic imagefrom the resulting data alone. The data are instead processed to providea sufficient signal-to-noise ratio for full-waveform inversion. So, forexample, we might sweep over 2-8 Hz, two octaves. The minimum acceptablebandwidth for an interpretable image is about 3 octaves.

It may further be desirable to choose to perturb the frequencies of thehumming sources to prevent unwanted interference of harmonics betweenthe seismic sources. For example, if the theory suggests that sourcesemitting waves 1.0 and 2.0 Hz should be employed, it might be preferredinstead to use 0.9 and 2.1 Hz, to avoid having one source frequencyconflict with the second harmonic of the other. Optionally, the harmonicor subharmonic output of a humming or narrowband source might beenhanced and use made of the harmonics or subharmonics as additionalhumming sources. So, for example, one source might simultaneouslygenerate waves having frequencies of 1.4 and 2.8 Hz.

In some embodiments, recording systems suffer from “tinnitus”, noisegenerated within the recording electronics, typically at a small numberof discrete frequencies. Due care should be taken to determine whetherthe recording system to be used suffers from tinnitus before deployment,and to measure its properties. Some equipment used in the field may alsogenerate strong energy at particular discrete frequencies. Theproperties of the ambient noise in an area to be surveyed ideally shouldbe measured before the surveying begins, to determine what frequenciesmight be locally compromised by man-made noise. As part of the surveydesign, the frequencies of the humming sources should be chosen to avoidany frequencies that are strongly polluted by narrowband noise, eitherfrom the environment or the recording equipment.

Multiple narrowband low-frequency sources 103, where used, may operateindependently or simultaneously. The narrowband low frequency sources103 may operate continuously or intermittently. Each narrowbandlow-frequency source 103 records the signal it is radiating, as thisinformation will be used when processing the acquired data. Thereceivers could be recorded continuously. The locations of all sourcesand receivers will, in some embodiments, also be recorded continuously.

The source vessel 106 tows the low frequency sources 103 along “shotlines” 118 (only one shown) during the acquisition. In the illustratedembodiment, the shot line spacing S_(s) is relatively coarse compared toconventional acquisition practices. In this context, “relatively coarse”in this particular embodiment means up to ˜400 meters, which is coarserthan conventional acquisition but close to the Nyquist criterion forfrequencies around 2 Hz or below. The shot lines are also placed out tovery wide source-receiver offsets relative to conventional practice.Again, in this context, relatively wide source-receiver offsets arethose up to ˜30 km. Alternative embodiments may use relatively coarseshot lines without wide source-receiver offsets or conventionally spacedshot lines with very wide source-receiver offsets.

As used herein, the term “coarse” is used to mean the opposite of“dense”. The term “dense” means sampled within the well-known Nyquistcriterion. Thus, the term “coarse” means sampled using spacing that doesnot meet the Nyquist criterion.

In some embodiments the receivers may be more closely spaced along an“inline” direction than they are along a “crossline” direction, and theshot lines are oriented parallel to the receiver crossline direction.That is, the shot inline direction is the receiver crossline direction,and the shot crossline direction is the receiver inline direction.Additional information regarding this particular design may be found inthe U.S. Patent Application having priority to U.S. ProvisionalApplication No. 62/086,362, entitled, “Box Wave Arrays in Marine SeismicSurveys”, filed on an even date herewith in the name of the inventorsAndrew J. Brenders, et al., and commonly assigned herewith.

The low frequency seismic sources 103 are also towed at a deep depthand, as a result of the heavy tow, at a steep tow angle. In theillustrated embodiment, the “deep depth” is ≥30 m, but this may vary inalternative embodiments from, for example, ˜30 m to ˜60 m, or in someembodiments up to ˜100 m. The tow angle is, for present purposes, thedeviation of the tow line from the vertical normal to the mean oceansurface 121. In the illustrated embodiment, the steep tow angle is ˜10°off the vertical, but this may differ among embodiments.

The heavy tow, if at a tow angle sufficiently close to the vertical, maygenerate a vortex induced vibration (“VIV”), a phenomenon known to theart. There are known VIV suppression techniques, but these can beoverwhelmed if the VIV becomes severe enough. Thus, the precise measureof the steep tow angle will vary amongst embodiments depending upon, forexample, the angle of the tow, the severity of the VIV, and the numberand effectiveness of VIV suppression techniques (if any) that areemployed. Those in the art having the benefit of this disclosure maydiscern and appreciate other factors, as well. Thus, a “steep” tow angleis one that is close enough to vertical that VIV starts to become aproblem. Note that the use of VIV suppression techniques may impact themeasure of the steep tow angle.

As mentioned above, the source vessel 106 may employ a VIV suppressiontechnique. There are several such techniques known to the art and anysuitable technique may be employed. However, one such, non-conventionaltechnique is employed by the embodiment of FIG. 4 and is shown in FIG.5. Note that the embodiment 400 of FIG. 4 tows the source 103 from theend, or stern, 405 of the source vessel 106′ rather than the side asdescribed above. Those in the art having the benefit of this disclosurewill be able to readily adapt the technique for use in embodimentsemploying a side tow rather than a stern tow.

The towing apparatus 500, shown in FIG. 5, generally comprises a winch505, a heave compensator 510, and an overboarding sheave 515. Theoverboarding sheave 515 comprises a fixed sheave 520 from which a freesheave 525 is suspended by a cable 555. The winch 505 raises and lowersthe source 103 from an umbilical 530 over the free sheave 525. Freemovement of the free sheave 525 indicated by the arrow 535 is permittedby the suspension of the free sheave 525 from the fixed sheave 520. Freemovement of the cable 555 as indicated by the arrow 540 is permitted bythe heave compensator 510 in conventional fashion.

The arrangement described immediately above separates the suspensionsystem 545 (i.e., the winch 505, fixed sheave 520, and free sheave 525in this embodiment) from the heave compensation system 550 (i.e., theheave compensator 510 in this particular embodiment). The heavecompensation is therefore “indirect” relative to conventional practicein which heave compensation is applied directly to the tow line. Theseparation permits, among other things, the motion of the free sheave525 to be controlled by the heave compensation system 550 with a cable555 that is thinner than the umbilical 530. In some embodiments, thisseparation also facilitates lifting the seismic source 103 out of thewater on the tow line 530 without the need for an overshot tool. It alsoremoves, in the illustrated embodiments, a mechanical terminationassociated with an electro-optical umbilical from the tow path andincreases the towline robustness generally. Other advantages andbenefits of this separation will become apparent to those skilled in theart having the benefit of this disclosure.

Still referring to FIG. 5, the umbilical 530 is encased in aVIV-suppression sheath 560. In the depicted embodiment, the sheath 560comprises a fibrous material that dissipates energy and dampensvibrations in the umbilical 530 induced by the relative movement of theumbilical 530 and the water column 127, in particular caused by motionof the source vessel 106′. The fibrous material may be, for example, aloose spun fiber or a fringed fiber, or any other VIV-suppression systemknown to the art.

The combination of the sheath 560 and the umbilical 530 will be toothick to pass through the heave compensator of a conventional system.Note that one of the benefits of separating the suspension system 545from the heave compensation system 550 is that the movement of the freesheave 525 can be controlled by the heave compensator 510 using a cable555 thinner than the umbilical 530. The cable 555 is thin enough to passthrough the heave compensation system. Thus, another benefit of such aseparation is that it permits the use of the VIV-suppression sheath 560with the umbilical 530.

In an alternative embodiment, not shown, the umbilical 530 is replacedby a tow line. The combination of tow line and VIV-suppression sheath560 is also too thick to pass through the heave compensation system. Thetow line supports the weight of the source 103, but unlike an umbilicaldoes not carry energy or telemetry. A separate umbilical line (notshown) is deployed from the vessel to carry these. The umbilical doesnot normally carry the weight of the device and extra umbilical line canbe deployed to ensure it will not be taut. The umbilical thus suffersmuch less from undesirable VIV, although in some embodiments VIVsuppression will also be used on the non-taut umbilical line tostabilize its motion through the water. The umbilical should be buoyant(to avoid entanglement with the source 103) and in some embodiments maybe strong enough to support the weight of the device so it can be usedfor deployment or recovery, and as an alternative backup support systemin case of a breakdown of the suspension system 545 or the tow line 530.

The distinction between a side tow and a stern tow is otherwise largelyan economic consideration. A side tow requires the use of a large, fixedcrane. Vessels, for example dive support vessels and constructionvessels, equipped with such cranes are known to the art and arecommercially available. They are, however, quite expensive. The sterntow can be performed with an offshore supply vessel, which is lessexpensive than dive support vessels and construction vessels.

Returning to FIG. 1, in acquisition, the source(s) 103 impart one ormore seismic signals 124 described above into the water column 127 topenetrate the seabed 112 where they interact with the subterraneanformation 130. The modified seismic signals 133 then propagate back tothe receiver array 136 disposed on the seabed 112 as described above.The modified seismic signals 133 are detected by the nodes 115 andrecorded as seismic data. The recorded seismic data are thencommunicated to a computing facility 139. This communication may be, forexample, by hard copy on a magnetic tape 142 or by transmission via asatellite 145.

The presently disclosed technique employs a low frequency source asdescribed above and, in some embodiments, may employ other types ofsources as well. In different frequency ranges, different types ofsources (e.g., impulsive versus swept-frequency) may perform better. Incircumstances where a swept-frequency device performs better, differenttypes of sweeps (broadband or narrowband) may be optimal. Thus, theremay be circumstances in which more than one type of source or mode ofoperation may be desirable.

Thus, in some embodiments, the low frequency source may be used inconjunction with an impulsive source—namely, airguns. The airguns arelouder than a correlated sweep from the low frequency device, at leastabove about 4 Hz. For lower frequencies, the microseismic backgroundnoise floor steadily increases and becomes the dominant factor belowabout 2 Hz. At some point, then, the narrowband humming acquisitionbecomes useful as discussed above. Some embodiments might even use avery narrow-bandwidth sweep (e.g., 1.7-1.8 Hz) instead of amonochromatic hum.

Embodiments using humming sources can also divide “humming” sweeps. Forexample, one device may hum continuously on a particular frequency whileanother device is “humming” at a different particular frequency. Athigher frequencies that are not quite so constrained by the backgroundnoise, a single low frequency source may cover two or more frequenciesby cycling between them, humming on one pitch, then another, in a cycle.If multiple low frequency sources are available, some embodiments maydeploy them and acquire data from them simultaneously, takingprecautions where the devices have overlapping frequencies.

However, humming acquisition does not need to use overlappingfrequencies. The frequencies can therefore be separated by bandpassfiltering. In that case the only overlap would be between the upperrange of a sweeping low frequency source and the lower range of anairgun. The low frequency sources would almost certainly be deployedfrom different vessels than the airguns, due to their differing towingrequirements. (The airguns would likely be towed from streamer vesselsthat were also towing streamers.) Even if they are not, the airguns andthe low frequency sources should be separable by simultaneous-sourcetechniques that take advantage of the very different source signaturesbetween airguns and the low frequency sweeps. And, if the airgun surveyis done at a different time, the separation is trivial.

FIG. 6 shows a spectrogram plot of this “simultaneous hum-sweep-bang”acquisition concept graphically. Note that the various different sourcesmay be operated simultaneously or separated in time, in any combination.The plurality of broadband (˜6-100 Hz) impulsive signals 600 indicateairguns firing. The sweeps (2-8 Hz) 610, bichromatic (“two-tone”) hums(0.98 and 1.4 Hz) 620, and monochromatic hum (0.7 Hz) 630 are allgenerated by a low frequency source such as the one discussed above.

Monochromatic hums have the advantage of putting the maximal energyavailable from a seismic source into a particular frequency. If the dataare divided into “shot points” during processing, complete freedom ismaintained on how to do that: the inline shot interval becomes aprocessing parameter. However, they have the disadvantage thatprocessing the resulting data may require modifications to a legacyprocessing workflow that assumes there are discrete, non-overlapping“shot points” and that sources do not move during a “shot”.

Two-tone hums have the advantage that one source can effectively providetwo interleaved shot lines in a single pass. They also have theadvantage of fitting more easily into legacy FWI workflows designed forimpulsive airgun data, but the two-tone hum must be designed properly togain this advantage.

Consider a proposed two-tone hum at frequencies of 1.55 and 2 Hz, to bedeployed from a source moving at 4 knots (=˜2 m/s). Each frequency mustrepeat before the source has moved greater than the desired shot inlinesample spacing for that frequency. The higher frequency requires a finersample spacing than the lower frequency, hence the upper frequency 2 Hzis controlling. At 2 Hz the Nyquist sample spacing for waves moving at awater velocity of 1500 m/s is 375 meters. The source moves this distancein 375 m/2 m/s=187.5 seconds, which sets an upper time limit for thelength of the complete two-tone hum.

If we wish to be able to approximate the source as stationary over thelength of time of a single-frequency hum, it should travel no furtherthan about the Nyquist sample spacing over 2, over this time interval.Thus for the upper frequency of 2 Hz, the maximum distance the sourcetravels should be about 375 m/2=187.5 meters, a distance a sourcetraveling at 4 knots travels in ˜94 seconds. For the lower frequency of1.55 Hz, the Nyquist sample spacing is ˜484 meters, a distance a sourcetraveling at 4 knots travels in ˜242 seconds, and half this is ˜121seconds.

We typically desire the two frequencies to have approximately equalsignal-to-noise ratios. If the signal-to-noise ratio declines at about30 dB per octave, 2.0/1.55 is ˜0.37 octaves, then the decline insignal-to-noise ratio from the higher to the lower frequency is about 30times 0.37 or 11 dB. The source always operates at its maximumamplitude, so the only way to make up the 11 dB is to increase thelength of time the signal is integrated over. Repeating cycles of thesource sum coherently (linearly with integration time). The noise over alonger period of time also sums, but incoherently (as the square root ofthe integration time), so the signal-to-noise ratio increases as thesquare root of the integration time. 11 dB is an amplitude factor of˜3.56, and the square of this is ˜12.7, implying the lower frequencyshould last for 12.7 times as long as the upper frequency to have equalsignal-to-noise ratio.

In practice, unless the two frequencies are relatively close togetherthis ratio is not achievable, because we also need to provide asufficient time gap for the standing wave pattern in the Earth generatedby the humming source at a particular frequency to decay away, so thatsignals from adjacent “shots” at that frequency don't overlap. This isabout 20 to 40 seconds for the deep water Gulf of Mexico. So in practicewe devote as much of the sweep as possible to the lower frequency, andthen emit the upper frequency just long enough to fill the minimum timegap required between consecutive lower-frequency hums. In this case, thetwo-tone hum thus should consist of 121 seconds at 1.55 Hz followed byabout 30 seconds at 2 Hz.

Another design choice is how quickly to sweep from one frequency to thenext. Partly this will depend on physical constraints (how quickly isthe device capable of changing frequency), but we may also choose totransition between frequencies more slowly than physically necessary, togain some of the advantages of a narrowband sweep.

What matters is achieving the signal-to-noise ratio over the range offrequencies required to meet the geophysical goals, as determined bymodeling. At best, the noise levels can only be estimated beforehand.Ambient noise at frequencies below about 2 Hz varies with the sea state,which depends on the weather. The weather cannot be accurately predictedvery far ahead, and it may be desirable to account for this unknownvariability during the survey design. So, for example, the survey designmay produce a range of profiles of varying amplitudes, lengths, and towspeeds, with the choice of which profile(s) to use on a given daydetermined in the field depending on, for example, the sea state,measured or estimated noise levels, currents, and tow-depth controlaccuracy. This example only serves to illustrate the general designprinciples. Different choices of frequencies, estimates of the slope ofthe signal-to-noise ratio, desired minimum and maximum source vesselspeeds, etc., will produce different results.

Returning to the “hum-sweep-bang” acquisition concept, in someembodiments, one or more low-frequency humming datasets and narrowbandsweeping datasets are combined with a conventional broadband dataset forprocessing. The one or more low-frequency humming datasets, one or morenarrowband sweeping datasets, and conventional broadband datasets may beacquired in any order. In particular, they may be acquired sequentially,or interleaved by shot lines, or interleaved within a shot line, oracquired simultaneously and separated using any of the standardtechniques known in the art, or in any combination of these. One or moreof the datasets may be “legacy” data, acquired previously for otherpurposes.

In some embodiments, the “conventional broadband” dataset may not useairguns as a source, but may instead use a different type of broadbandsource, for example a marine loudspeaker source that emits broadbandpseudorandom noise. In other embodiments, the “conventional broadband”source may be sweeping sources that sweep over a sufficient range tobecome broadband, or consist of a mixture of sweeping sources thattogether are broadband. In this case the entire desired frequency rangemay be covered by just the humming and sweeping sources in FIG. 6.

In marine “hum-sweep-bang” or “hum-sweep” acquisition, the receivers maybe ocean-bottom nodes or ocean-bottom cables, but may also be streamers,wave gliders, receivers in a borehole, etc. In some embodiments,different sources may be recorded into distinct receivers. For example,the impulsive broadband seismic signals might be recorded byconventional streamers (which may have sufficiently low noise atfrequencies above ˜6 Hz to be adequate for the purpose), but the hummingand sweeping seismic signals by ocean-bottom nodes, or low-noisedeep-tow streamers.

Although described in terms of marine acquisition, those of ordinaryskill in the art will also readily appreciate that this “hum-sweep-bang”or “hum-sweep” acquisition concept could equally well apply to landacquisition, with land vibrators taking the role as the humming andsweeping sources, dynamite as the impulsive source, and geophones as thereceivers.

In one particular embodiment, the low frequency seismic data acquired asdescribed above is processed as disclosed in U.S. application Ser. No.14/525,451, entitled, “Two Stage Velocity Model Generation”, and filedOct. 28, 2014, in the name of the inventors Andrew J. Brenders andJoseph A. Dellinger (Docket No. 500453). As disclosed therein, theprocess is applicable to the development of models of all manner ofsubsurface attributes. Those skilled in the art having the benefit ofthis disclosure will appreciate how to modify the acquisition taughttherein to incorporate the teachings disclosed herein and how to applythe disclosed processing technique to the resulting seismic data.

Another acquisition technique is taught in U.S. application Ser. No.13/327,524, entitled, “Seismic Acquisition Using Narrowband SeismicSources”, filed Dec. 15, 2011, in the name of the inventors Joseph A.Dellinger et al., published Jun. 21, 2012, as U.S. Patent Publication2012/0155217. Those skilled in the art having the benefit of thisdisclosure will also appreciate how to modify the acquisition taughttherein to incorporate the teachings disclosed herein.

The following patent applications and patents are hereby incorporated byreference for those portions that are listed and for the purposes setforth as if set forth verbatim herein.

U.S. application Ser. No. 14/525,451, entitled, “Two Stage VelocityModel Generation”, and filed Oct. 28, 2014, in the name of the inventorsAndrew J. Brenders and Joseph A. Dellinger (Docket No. 500453) for itsteachings regarding the processing disclosed in FIGS. 1 and 7 thereinand the associated text, and more particularly ¶¶[0025]-[0064], and[0079]-[0111].

U.S. application Ser. No. 13/327,524, entitled, “Seismic AcquisitionUsing Narrowband Seismic Sources”, filed Dec. 15, 2011, in the name ofthe inventors Joseph A. Dellinger et al., published Jun. 21, 2012, asU.S. Patent Publication 2012/0155217, and commonly assigned herewith forits teachings regarding data acquisition located at ¶¶[0024]-[0040],[0054]-[0059], [0065]-[0088] modified as taught herein.

U.S. Pat. No. 6,975,560, entitled, “Geophysical Method and Apparatus”,and issued Dec. 13, 2005, to BP Corporation North America Inc., asassignee of the inventors Eivind W. Berg et al., for its teachingregarding the deployment of nodes from a carrier using an ROV and, inparticular, the teachings at column 1, line 30 to column 2, line 9;column 2, line 21 to column 3, line 37; column 4, line 57 to column 5,line 16; column 5, line 27 to column 8, line 45, and the drawingsreferenced therein.

U.S. Pat. No. 8,387,744, entitled, “Marine Seismic Source”, and issuedMar. 5, 2013, to BP Corporation North America Inc., as assignee of theinventors Mark Harper et al., for its teaching regarding the design andoperation of a humming and narrowband seismic source at column 5, line62 to col. 12, lines 46.

U.S. application Ser. No. 14/515,223, entitled, “System and Method forResonator Frequency Control by Active Feedback”, filed on Oct. 15, 2014,in the name of the inventors Mark Francis Lucien Harper; Joseph AnthonyDellinger.

the U.S. Patent Application having priority to U.S. ProvisionalApplication No. 62/086,362, entitled, “Box Wave Arrays in Marine SeismicSurveys”, filed on an even date herewith in the name of the inventorsAndrew J. Brenders, et al., (Docket No. 500444) and commonly assignedherewith.

To the extent that any patent, patent application or paper incorporatedby reference herein conflicts with the present disclosure, the presentdisclosure controls.

In several places the description uses the modifier “approximately” orits mathematical equivalent symbol “˜”. This is a recognition that willbe appreciated by those in the art that precise numbers can be difficultin this type of endeavor. For example, in towing the low frequencyseismic sources, currents, temperatures, salinity, and otherenvironmental conditions may fluctuate between deployment and retrievalmaking it difficult to achieve and maintain a desired numerical valuefor some operating parameters. Similarly, these types of parameters willvary amongst survey areas as will the numerical values for the variousquantities. Those skilled in the art having the benefit of thisdisclosure will appreciate these kinds of variations and so appreciatethe approximation and what it means rather than crisp numerical values.

Where reference is made herein to a method comprising two or moredefined steps, the defined steps can be carried out in any order orsimultaneously (except where context excludes that possibility), and themethod can also include one or more other steps which are carried outbefore any of the defined steps, between two of the defined steps, orafter all of the defined steps (except where context excludes thatpossibility).

Other embodiments of the invention will be apparent to those skilled inthe art from consideration of the specification and practice of theinvention disclosed herein. It is intended that the specification andexamples be considered as exemplary only, with a true scope and spiritof the invention being indicated by the following claims.

What is claimed is:
 1. A method for use in seismic surveying,comprising: imparting a plurality of low-frequency seismic signals intoa geological formation; imparting a plurality of broadband seismicsignals into the geological formation, wherein the plurality oflow-frequency seismic signals and the plurality of broadband seismicsignals are each imparted at different frequencies, and wherein afrequency range of the plurality of low-frequency seismic signals areselected to augment a frequency range of the broadband seismic signals;receiving returned seismic energy of the plurality of low-frequencyseismic signals and the plurality of broadband seismic signals afterinteracting with the geological formation; and recording the returnedseismic energy.
 2. The method of claim 1, wherein imparting theplurality of low-frequency seismic signals includes generating amonochromatic hum.
 3. The method of claim 1, wherein imparting theplurality of low-frequency seismic signals includes generating abichromatic hum.
 4. The method of claim 1, wherein imparting theplurality of low-frequency seismic signals comprises: imparting aplurality of humming seismic signals into the geological formation; andimparting a plurality of swept seismic signals into the geologicalformation.
 5. The method of claim 1, where each of the plurality of lowfrequency signals are imparted by one or more low-frequency seismicsources that operates at a single frequency.
 6. The method of claim 4,wherein the frequency range of the broadband seismic signals is greaterthan the frequency range of the swept seismic signals.
 7. A system forseismic surveying, comprising: a low-frequency seismic source configuredto impart a plurality of low-frequency seismic signals into a geologicalformation; a broadband seismic source configured to impart a pluralityof broadband seismic signals into the geological formation, wherein theplurality of low-frequency seismic signals and the plurality ofbroadband seismic signals are each imparted at different frequencies,and wherein a frequency range of the plurality of low-frequency seismicsignals are selected to augment a frequency range of the broadbandseismic signals; one or more receivers configured to receive returnedseismic energy of the plurality of low-frequency seismic signals and theplurality of broadband seismic signals after interacting with thegeological formation; and a recording device configured to record thereturned seismic energy.
 8. The system of claim 7, wherein the pluralityof low-frequency seismic signals and the plurality of broadband seismicsignals are imparted into the geological formation simultaneously. 9.The system of claim 7, wherein the plurality of low-frequency seismicsignals are imparted into the geological formation after the pluralityof broadband seismic signals.
 10. The system of claim 7, wherein theplurality of low-frequency seismic signals are imparted into thegeological formation before the plurality of broadband seismic signals.11. The system of claim 7, further comprising a plurality oflow-frequency seismic sources, wherein the plurality of low-frequencyseismic sources comprises a humming seismic source and a swept seismicsource, wherein the humming seismic source is configured to impart aplurality of humming seismic signals into the geological formation, andwherein the swept seismic source is configured to impart a plurality ofswept seismic signals into the geological formation.
 12. The system ofclaim 7, wherein the low-frequency seismic source is configured togenerate a monochromatic hum.
 13. The system of claim 7, wherein thelow-frequency seismic source is configured to generate a bichromatichum.
 14. The system of claim 7, wherein the low-frequency seismic sourceoperates over a narrowband range of low frequencies.
 15. A system forseismic surveying, comprising: a plurality of low-frequency seismicsources configured to impart a plurality of low-frequency seismicsignals into a geological formation, wherein the plurality oflow-frequency seismic sources comprises a humming seismic source and aswept seismic source; a plurality of broadband seismic sourcesconfigured to impart a plurality of broadband seismic signals into thegeological formation, wherein the plurality of low-frequency seismicsignals and the plurality of broadband seismic signals are each impartedat different frequencies, and wherein a frequency range of the pluralityof low-frequency seismic signals are selected to augment a frequencyrange of the broadband seismic signals; a plurality of receiversconfigured to receive returned seismic energy of the plurality oflow-frequency seismic signals and the plurality of broadband seismicsignals after interacting with the geological formation; and a recordingdevice configured to record the returned seismic energy.
 16. The systemof claim 15, wherein the humming seismic source is configured to cyclebetween two or more discrete frequencies.
 17. The system of claim 15,wherein the swept seismic source is configured to sweep over anarrowband range of low frequencies.
 18. The system of claim 15, whereinthe plurality of broadband seismic signals are at least one of impulsiveseismic signals or swept seismic signals.
 19. The system of claim 15,wherein plurality of broadband seismic signals are pseudorandom noiseseismic signals.
 20. The system of claim 15, wherein the frequency rangeof the plurality of broadband seismic signals is greater than thefrequency range of the plurality of swept seismic signals.
 14. Thesystem of claim 12, wherein the humming source is configured to generatea bichromatic hum.
 15. The system of claim 12, wherein the hummingsource is configured to impart the humming seismic signals at afrequency different from the swept seismic signals.
 16. The system ofclaim 12, wherein the lower limit of the useful frequency range of theswept seismic signals is greater than the upper limit of the usefulfrequency range of the humming seismic signals.
 17. The system of claim12, further comprising a broadband seismic source configured to impartbroadband seismic signals into the geological formation; and wherein thereceiver is configured to receive returned seismic energy of thebroadband seismic signals after interacting with the geologicalformation.
 18. The system of claim 17, wherein the broadband sourcecomprises one of an impulsive seismic source and one or more sweptseismic sources.
 19. The system of claim 17, wherein the broadbandseismic signals are pseudorandom noise seismic signals.
 20. The systemof claim 17, wherein the frequency range of the broadband seismicsignals is greater than the frequency range of the swept seismicsignals.